Fortnightly - Nuclear generationhttp://www.fortnightly.com/tags/nuclear-generation
enCoal's Black Futurehttp://www.fortnightly.com/fortnightly/2008/03/coals-black-future
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Turbulent politics and market trends cloud prospects for coal-fired power.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Eric Spiegel, et al.</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Energy Risk &amp; Markets</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Eric Spiegel</b> is a senior vice president, <b>James C. Hendrickson</b> a vice president and <b>Andre Begosso</b> a principal with Booz Allen Hamilton in McLean, Va., and Troy, Mich. Contact Eric at <a href="mailto:speigel_eric@bah.com">speigel_eric@bah.com</a>, Jim at <a href="mailto:hendrickson_james@bah.com">hendrickson_james@bah.com</a> and Andre at <a href="mailto:begosso_andre@bah.com">begosso_andre@bah.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 2008</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0803/images/0803-ERM-fig1.jpg" width="2025" height="1108" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/0803/images/0803-ERM-fig2.jpg" width="1344" height="893" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0803/images/0803-ERM-fig3.jpg" width="1356" height="785" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>For a century, coal-fired power plants have generated most of the United States’ base-load electricity. At times along the way, alternatives emerged and flourished briefly—first oil-fired generation, then nuclear, and most recently natural gas. But these waves ended badly, often bringing financial ruin to the companies that had championed them too enthusiastically. Meanwhile, the more-cautious companies that kept on building coal-fired plants have survived and prospered.</p>
<p>Now, coal faces more uncertainty than any other base-load generating source. Two new factors, hitherto irrelevant to the U.S. industry, will shape future generation investment—imports of liquefied natural gas (LNG) and greenhouse-gas (GHG) restrictions. Taken together, they point to a bleak future for coal unless its technology advances dramatically … or a political consensus fails to emerge.</p>
<h4>GHG Restrictions</h4>
<p>A decade ago, global warming was fodder for stand-up comics on late-night television. This year, both of the front runners in the Democratic campaign for president have endorsed draconian long-term restrictions on GHG emissions (reductions of 80 percent from 1990 levels by 2050). And the presumed Republican nominee, John McCain, has endorsed restrictions nearly as severe. Significant legislation seems more likely than not in the 2009 to 2010 time period, even if its exact shape is now unclear.</p>
<p>If GHG emissions are restricted, the burden of adjustment likely will fall on the nation’s fleet of coal-fired power plants. Other sectors of the economy would continue expanding their emissions as they grow, albeit at a slower rate due to CAFE limits, <i>etc.</i>, while the coal-fired fleet brings down its emissions far enough and fast enough to offset capacity expansion and still meet economy-wide reduction targets.</p>
<p>The reason is economic. In most sectors, reducing the emissions from a stationary source requires separating out and sequestering the greenhouse gases from its flue-gas stream. The cost of doing that with today’s technology generally exceeds $90 to $100 per ton sequestered. (Note: All dollar quantities are expressed in 2007 dollars and all greenhouse gas quantities are expressed in tons of CO<sub>2 </sub>equivalent.) However, the power-generation sector has another alternative available—replacing existing coal-fired plants with new-built plants using an alternative generation technology with much lower GHG emissions, such as natural-gas combined cycle.</p>
<p>At current prices, the all-in cost of doing so amounts to only $30 to $40 per ton of GHG emissions avoided. So regulators have strong incentives to meet their emissions targets by squeezing coal-fired plants nearly to extinction before significantly restricting other stationary sources.</p>
<p>That could happen fairly rapidly. If U.S. emissions merely are capped at 2006 levels with no actual reductions, then expansion elsewhere in the economy would cause about half of today’s coal-fired production to be replaced over the next 20 years <i>(see Figure 1)</i>. And more aggressive targets would lead to correspondingly faster replacement.</p>
<p>Other considerations will help accelerate this transition. In particular, Phase II of the Clean Air Act takes effect in 2010, requiring nearly 200 additional existing coal plants to retrofit to reduce sulfur dioxide and nitrogen oxide emission levels. The additional pressure of prospective GHG restrictions makes those investments even less attractive.</p>
<p>The logic of GHG regulation cuts both ways. Most politicians favor implementing GHG restrictions through some sort of economy-wide cap-and-trade scheme that puts a market price on GHG-emission allowances. But at what price? The lowest price that will hold economy-wide emissions flat (much less reduce them) must be high enough to motivate the replacement of existing coal-fired plants. At today’s natural-gas prices, that means emissions allowances trading at $30 to $40 a ton or higher. Conversely, an allowance price in that range will motivate ample volumes of conversion, so the price need not go much higher for many years. In effect, the price of natural gas sets the price of emissions allowances, over a fairly-wide range.</p>
<p>This is happening in other jurisdictions. The European Union (EU) has imposed a broad-based cap-and-trade program on its GHG emissions. That program had a clumsy start, with an unsustainable level of emission allowances issued in the first round. But it now has moved to a second round, with allowances more closely managed. The market has priced these second-round allowances at $30 to $40 a ton, because the cost of converting from coal to natural gas is roughly the same in Europe as it is in North America.</p>
<p>It’s worth noting how all this would concentrate America’s response to greenhouse gases in a few key regions. The mix of coal-fired generation ranges from about 80 percent coal-fired in ECAR and MAPP down to around 15 percent in California, New York and New England generally. In particular, an economy-wide cap-and-trade program would have coal-light regions buying up emissions allowances from coal-heavy regions, which would use the proceeds to fund conversion away from coal.</p>
<p>California’s current dilemma illustrates this point nicely. The state has essentially no coal-fired generation within its borders, and only imports a limited amount of coal-generated power. Yet California recently has launched an initiative to roll its GHG emissions back to 1990 levels by 2020—an anticipated 25 percent reduction. If this reduction must come from actually abating in-state sources such as industrial plants and vehicle tailpipes, then the abatement costs likely will run to $100 a ton or more. But if in-state sources can meet their reduction targets by paying for abatements in coal-fired generation elsewhere, then the same GHG reduction can be achieved for only $30 to $40 a ton. (It remains uncertain if California will accept such out-of-state abatements as an integral part of its GHG program.)</p>
<h4>LNG Landing</h4>
<p>Of course, predictions of coal’s decline assume alternative generation technologies and fuels will be available at reasonable costs—natural gas, or perhaps nuclear. For natural gas, the sticking point is supply availability at a reasonable price.</p>
<p>Historically, a price spread has existed between coal and natural gas. In the 1990s, when the dynamics of both markets were driven by push supply rather than pull demand, the spread varied between $1.00 and $1.50 per million Btu (MMBtu). At that spread, natural gas promised a cheap, abundant and clean alternative to coal. Low gas prices, relatively low plant construction costs, and growing public concerns over environmental issues made gas-fired plants the technology of choice. Investment in new coal-fired plants stopped for almost a decade, while natural-gas combined-cycle capacity increased rapidly.</p>
<p>The resulting boost in consumption, combined with declining traditional production, significantly increased natural gas prices to $7 to $8 from $2 to $3 per MMBtu in the late 1990s. While coal prices also have been under pressure from global demand and associated transportation costs, the coal-to-gas spread nonetheless has risen to about $5 per MMBtu.</p>
<p>At these prices, natural gas generation is uncompetitive versus conventional coal, even excluding GHG issues; it would have to decline to between $5 and $6 <i>(see Figure 2)</i>. But such price levels are unlikely based on North American sources, due to sustained demand from industrial consumers, physical production declines, weather-driven disruptions, and seasonal demand uncertainties. In fact, core-reserve depletion, combined with the increased reliance on non-conventional production, will lead to future lower levels of production.</p>
<p>Thus, while North America historically has been self-sufficient in gas, that’s changing. Incremental supplies will come in the form of LNG imported from overseas. The International Energy Agency anticipates the United States will import about 6 trillion cubic feet a year of LNG by 2030—about equal to the amount of additional natural gas needed to replace coal-fired generation under a flat-emissions restriction.</p>
<p>As the source of incremental supply, LNG likely will set the long-term price for all U.S. natural gas. But LNG is a globally-traded commodity with a more-or-less global price like crude oil, not a collection of separate local and regional markets like electricity. So the U.S. will be a price taker in this global market.</p>
<p>For at least the next few decades, the incremental global demand for LNG will continue to be for power generation—as it will be in the United States. Nuclear generation stands as the principal economic alternative to natural gas as a source of low-GHG electricity, putting an effective cap on LNG prices globally.</p>
<p>Of course, nuclear’s prospects in any jurisdiction depends as much on political and social factors as they do on economic questions. For example, France generates 80 percent of its electricity from nuclear, while neighboring Germany anticipates phasing out its remaining nuclear generation. But the global nature of the LNG market makes the nuclear alternative effective everywhere. In other words, if the global price of LNG (and the linked price of GHG emissions) rises too far, then some jurisdiction somewhere in the world will shift its next power plant from gas-fired to nuclear, and all jurisdictions will benefit from the resulting price cap.</p>
<p>In short, the emerging global market for LNG helps ensure that the United States has an alternative to coal-fired generation that’s acceptable from both an economic and a political standpoint. And that makes it less likely that regulatory pressure on greenhouse-gas emissions will abate.</p>
<h4>Shadow of the Future</h4>
<p>Uncertainty about future U.S. policy towards greenhouse-gas emissions has proven more burdensome to the electricity sector than any actual policy that’s likely to be adopted. For some years, new generation-capacity development has been at a standstill, with more capacity additions being cancelled than announced. Last year that eased somewhat, with a significant increase in new generating-capacity announcements. Interestingly, coal is a key component, but the number of corresponding cancellations demonstrates widespread uncertainty. The commitment toward gas, nuclear and renewables has been aggressive and appears poised to overtake coal <i>(see Figure 3)</i>.</p>
<p>Europe provides a current example of the uncertainty that blights investment. The original European scheme for restricting GHG provided assurance that existing facilities would have a gradually decreasing stream of emissions allowances without charge. Now Brussels is considering whether to auction off the allowances rather than award them to existing sites. The economic consequences are huge for existing sites with stranded investments. And the prospect that any new-build plant could become similarly stranded must stand as a deterrent to potential investors.</p>
<h4>Emerging Technologies</h4>
<p>The future of coal-fired generation, under most commonly discussed carbon regimes, appears bleak based on the extremely high cost of separating post-combustion GHG from a flue-gas stream using today’s technology. Over the long term, prospects for carbon capture and sequestration (CCS) could improve dramatically. Effective CCS technology should be available for about $30 a ton sometime after 2020, versus about $100 a ton today.</p>
<p>More broadly, coal gasification could offer a potential pathway for employing coal that avoids the need for expensive post-combustion separation. Unfortunately, traditional gasification technologies with CCS will become economic only when natural gas prices exceed $11, compared to $7 to $8 today. And as discussed, alternatives such as nuclear generation make sustained gas prices that high seem unlikely.</p>
<p>Non-traditional catalyzed gasification technologies may be emerging that could provide a pathway from coal to natural gas at perhaps $5 per MMBtu with CCS. Today, these technologies exist only at lab-bench scale, but their potential for an extraordinary impact should not be overlooked. That impact would cut two ways. On one hand, it would revive the fortunes of coal mining, replacing LNG as the source of incremental gas supplies. On the other hand, it would accelerate the shift away from conventional coal-fired generation.</p>
<h4>Coal-Pit Politics</h4>
<p>In a recent “carbon war game” exercise among seven major U.S. investor-owned utilities, GHG restrictions triggered a transition away from coal-fired generation, driving up real electricity prices by 5 percent a year for a decade in the coal-heavy markets (see “<a href="http://www.fortnightly.com/fortnightly/2007/12/carbon-wargames">Carbon Wargames</a>,” <i>Fortnightly</i>, December 2007). War game participants broadly agreed that increases of that magnitude would set off a political firestorm. How likely is such an outcome, and how likely is it to trigger a reversal of GHG policy?</p>
<p>The answer seems to depend heavily on the details of the GHG-restriction program. If it consists of a national <i>economy-wide</i> cap-and-trade program, and existing power-plant operators receive a continuing allocation of emissions allowances proportional to their historical emissions, only stepped down gradually in proportion to the national cap, then the burden will be fairly limited. In effect, the rest of the economy will subsidize the transition to non-coal generation by purchasing allowances from the departing coal plants. However, if the cap-and-trade is not economy-wide, or if the allocations largely are auctioned off, then the burden will fall directly on the coal-heavy regions. And the resulting price fly-up likely will cause a vigorous push-back from both households and businesses in the affected areas. This is not an unlikely scenario and strengthens the resilience of traditional coal—changing the game.</p>
<p>National security also may raise a whole different political issue. On one hand, increasing LNG imports would make the United States’ economy—and the larger world economy—ever more dependent on uninterrupted supplies from some of the world’s most politically unstable regions. On the other hand, the United States and the world already depend on the same regions for exports of petroleum liquids, so how much additional risk do LNG imports really impose?</p>
<p>Additionally, these projections anticipate business as usual largely will continue in both commerce and politics. That could change. If the intertwined issues of energy affordability, energy security and climate change achieve enough political salience, the federal government (and others) might commit large-scale resources to advancing the relevant technologies rapidly. Breakthroughs in the separation of greenhouse gases, or catalyzed coal gasification, could re-arrange the playing field quickly.</p>
<p>If and when GHG restrictions materialize, there’s little doubt that much of the burden will fall on coal-fired generation. With today’s prices and technologies, that would lead to substantial shrinkage of the coal-fired power fleet over the next two decades. Non-traditional gasification and CCS technologies hold promise for altering that path, but so do reinvigorating nuclear development, expanding renewables and intensifying demand management. The main dilemma for most utilities and generation developers is handicapping this technology race, as well as the associated politics. In short, it’s easier to envision the world of electricity generation after 2030 than to find a satisfactory strategy to get there.</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/coal">Coal</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/energy-risk-markets">Energy Risk &amp; Markets</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0803/images/0803-cvr.jpg" width="1121" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/ccs">CCS</a><span class="pur_comma">, </span><a href="/tags/clean-air-act">Clean Air Act</a><span class="pur_comma">, </span><a href="/tags/ghg">GHG</a><span class="pur_comma">, </span><a href="/tags/international-energy-agency">International Energy Agency</a><span class="pur_comma">, </span><a href="/tags/nuclear">Nuclear</a><span class="pur_comma">, </span><a href="/tags/nuclear-generation">Nuclear generation</a> </div>
</div>
Sat, 01 Mar 2008 05:00:00 +0000puradmin13835 at http://www.fortnightly.comAmerica's Canadian Problemhttp://www.fortnightly.com/fortnightly/2003/04-0/americas-canadian-problem
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>U.S.-Canada electricity trade is shrinking, and some American companies may be left without their megawatts for the summer.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Charles W. Thurston</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 15 2003</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><p></p>
<h3>U.S.-Canada electricity trade is shrinking, and some American companies may be left without their megawatts for the summer.</h3>
<p>The megawatt flow to the United States from Canada is winding downward despite the continuing U.S. requirement for substantial peak demand, energy experts say. This downward trend in cross-border electricity trade is due in large part to rising demand from Canada's economic growth. And with more natural gas-fired generation starting up on both sides of the border, signs also indicate that during the rest of the decade, the United States and Canada increasingly will become less dependent on one another for peak demand electricity needs.</p>
<p>Traditionally, as U.S. summer peak demand drives the market to attractive, if not volatile, pricing levels, Canada exports between 6 percent and 8 percent of its total electricity generation to a host of U.S. states. Then, during the winter (Canada's peak demand period, except for heavily air-conditioned Ontario), U.S. generators export electricity across the well-connected border to the north, in a natural complement of seasonal trade.</p>
<p>Last year, Canada exported a total of 36.7 million megawatt-hours (MWh) to the United States, at an average price of Cdn$46.00 (about US$30.00) per MWh, according to statistics compiled by Mary-Jane Sam, the statistical research officer in the Commodities Business Unit at Canada's National Energy Board (NEB), in Calgary. And in 2002, Canada imported 13.9 million MWh from the United States at an average price of Cdn$36.18 per MWh. This trade resulted in a net Canadian export of 20.8 million MWh, which netted some Cdn$1.4 billion, mostly for hydroelectric generators, which purchase electricity from the United States when prices are low and pump water up into reservoirs with available capacity.</p>
<p>Comparing 2002 trade with 2001, net U.S. imports are down. During full-year 2001, Canada exported 40.1 million MWh at an average price of Cdn$100 per MWh, while importing 17.9 million MWh at an average price of Cdn$101. The net result in 2001 was 22.3 million MWh of Canadian exports worth Cdn$2.4 billion.</p>
<p>Looking forward for at least the mid term, the trend in net imports by the United States will continue downward, says Ivan Harvie, a senior engineer at the NEB, in Calgary. "The number one reason why trade will decline is that 70 percent of Canadian exports come from hydro and it takes many years to bring on new hydro capacity. So as the demand load grows in Canada, it will leave less available for exports to the United States," he says.</p>
<p>Keeping pace with demand growth in both the United States and Canada was once a higher strategic priority for Canadian generators. "There was a time when Ontario wanted to develop as a hub for the (cross-border) region and be a big player in the export market; they even were looking at buying transmission assets in the United States. But after the Enron and California effects, the exuberance has dropped off," Harvie says. According to a recent draft NEB analysis of Canada's future energy demand through the year 2025, total electricity exports are projected to drop to less than 4 percent of total electricity generation, or about half the historic level.</p>
<h3>Peak Demand Problems in Ontario</h3>
<p>Ontario in particular is driving up peak load during the summer months, when North American prices are at their highest. In August 2002, Ontario logged an all-time peak of 25,414 MW. As a result, other provinces, including neighboring Quebec-the largest electricity exporter to the United States-supply Ontario during the summer, thus reducing available energy for export.</p>
<p>Ontario is not building enough new capacity to end its peak demand problem anytime soon, one analyst suggests. "The Ontario market is forecast to have a capacity shortfall as early as 2005, even with the 3,500 MW of nuclear capacity that is scheduled to return to service and with the 1,000 MW of independent generating capacity currently under construction," says John Dalton, a managing director at Navigant Consulting in Toronto. The timetable for the return of the nuclear plants could suffer from political factors as well as mechanical factors, however, further exacerbating peak load problems in Ontario.</p>
<p>Quebec leads Canadian provincial exporters, having sold 14.7 million MWh to the United States last year, followed by British Columbia with 7.9 million MWh, Manitoba with 7.4 million MWh, and Ontario with 2.4 million MWh. None of the other provinces that exported to the United States last year, including Alberta, New Brunswick, Nova Scotia, and Saskatchewan, sold more than a few hundred thousand megawatt-hours.</p>
<p>Still, Newfoundland and Labrador could become substantial exporters if negotiators agree on the terms of the proposed Gull Island hydroelectric project. This 2,000 MW project is located on the Churchill River in Labrador and carries an estimated cost of Cdn$4 billion for the construction of the dam and a transmission line to Ontario; completion is estimated six years from construction start. "At least initially, some of the electricity from Gull Island could be exported," Dalton says.</p>
<p>The states that imported more than 1 million MWh from Canada last year, according to Sam's NEB statistics, include:</p>
<ul>
<li>New York with 13.9 million MWh;</li>
<li>North Dakota/Minnesota with 7.4 million MWh;</li>
<li>Washington with 4.4 million MWh;</li>
<li>Maine with 3.9 million MWh;</li>
<li>Vermont with 2.1 million MWh;</li>
<li>California with 1.9 million MWh; and</li>
<li>Oregon with 1.5 million MWh.</li>
</ul>
<p>While the volume of Canadian electricity supplied to the United States as a whole may be diminishing, much of the current supply will continue to be a critical component in the planning for energy-short regions like New England. In an October 2002 projection of the next four years' worth of demand and supply for the New England Power Pool (Nepool), ISO New England has modeled summer peak month supply plans that include a flow of 1,450 MW from Hydro Quebec and New Brunswick, the lion's share of all planned purchases for Nepool.</p>
<h3>U.S. Supplies Provinces, but Deregulation Inspires Little Cross-Border Trade</h3>
<p>A few states are major exporters of electricity to Canadian provinces, mostly during the winter months. In 2002, Washington led all state exporters with 5.6 million MWh sold to Canada, followed by New York with 3 million MWh and North Dakota/Minnesota with 2.1 million MWh, NEB statistics show.</p>
<p>Given the plethora of merchant plant projects that have been funded over the last several years in the United States, it seems likely that some U.S. states along the Canadian border could compete with gas-fired generators in the provinces for peak load demand in Canada, since transmission costs could be similar. U.S. gas-fired projects obviously cannot compete with Canadian hydro projects, given current natural gas prices. But natural gas seems to be the preferred fuel source for the planned conversion of many of Canada's coal-fired units, which could further level the cross-border playing field for trade in gas-fired electricity generation.</p>
<p>Yet with the advent of Canadian deregulation, the number of marketers there has risen dramatically, which nominally would permit the number of significant exporters to rise as well. But only a handful of the largest hydro-based utilities control most electricity exports. "We used to have just a few provincial players in the market, but in the last 10 years, we've had about 40 new marketers enter, so there is a lot more trading back and forth. Still, the total volume of exports by those 40 is less than 1 percent of the total of cross-border trade," Harvie estimates.</p>
<p>The failure of the new marketers to gain a stronger foothold in the export market may have more to do with regulation than with competition, though. "The electric utility industry restructuring that has taken place over the past decade has not resulted in increased Canadian electricity exports; indeed, exports have declined since the mid-1990s," Harvie says. On the other hand, U.S. deregulation has helped standardize the North American regulatory norm, others suggest. "Dozens of Canadian companies have made submissions to the FERC on standard market design, because they don't want to see any trade barriers," one consultant says.</p>
<p>Canada's unbundling of still-regulated transmission from distribution and generation, however, may help the export potential over the mid to long term, since transmission capacity is one limit to cross-border trade growth. But investments in generation in provinces like Ontario, where a retail electricity price cap has been imposed through 2006, could discourage enough investment to preserve the province's peak demand problem for years to come.</p>
<p>Whether sufficient utility capital resources will be available to make needed investments in generation and transmission also is an open question, given Canadian regulations, which permit high levels of utility debt. Standard &amp; Poor's is reanalyzing the impact of regulation on the credit ratings of Canadian utilities, with an eye toward the possibility of higher, investment-grade ratings. Nonetheless, "Investor-owned Canadian utilities are among the most highly-levered utilities in S&amp;P's global ratings universe, with financial profiles that are noticeably weaker than those of their global peers," notes Thomas Connell, a credit analyst at S&amp;P in Toronto. "Many Canadian utilities typically have lower equity layers in their capital structures than their global peers, with total debt in some cases representing 60 percent to 70 percent of total capital," he said in early March.</p>
<p>The retail price cap in Ontario has had a singularly negative impact on investment in new generating capacity in the province, Dalton says. "Conditions in the power markets make the development of new capacity particularly difficult. These conditions include the retail price freeze imposed by the Ontario government in November 2002 which adversely affects investor confidence, the financial woes of merchant generators which make equity investments difficult, and lenders' requirement that the output of new generators be largely contracted," he says.</p>
<h3>Alternative Fuel Sources: Does Canada Have More To Give?</h3>
<p>Nonetheless, Canada is rich in energy resources and the hydroelectric potential that could generate much more electricity. Canada's hydropower association suggests that the country still has twice as much hydroelectric potential as the 50,000 MW that already have been developed, representing almost a third of all generation capacity in the country. But the long lead-time in constructing a hydro facility typically requires long-term purchase contracts, which are no longer a staple of the market. Thus, electricity generated from nucle-ar, natural gas, oil sands, coal, wood, and wind sources could gain a larger share of the total Canadian generation volume.</p>
<p>One major new alternative fuel project in the early stages of development is based in oil sands-rich Alberta. Northern Lights Transmission hopes to construct a direct current electricity transmission line from Alberta to the U.S. Pacific Northwest for electricity export by 2008. The electricity the line would carry would be generated largely from cogeneration units, which also would produce the steam used to recover oil from the sands. The planned capacity of the 1,000-mile long transmission line is 2,000 MW, plus or minus 500 kilovolts. Feasibility studies under negotiation are assessing routing alternatives for customers in Canada and in the United States, as well as potential investors, says Glenn Herchak, a spokesman for TransCanada, in Calgary, the lead developer of the project.</p>
<p>The oil sands project could be important for Canada's total energy trade balance, because Northern Lights is projected to be capable of producing more than 300 billion barrels of oil, a volume which is 40 billion more barrels than is recoverable in the Middle East and 14 times more than the recoverable oil that exists in the United States, the developer claims. Northern Lights Transmission currently is a partnership between Trans-Canada and AltaLink; AltaLink is a consortium comprising SNC Lavalin Energy, Trans-Elect Inc., Ontario Teachers' Pension Plan, and Macquarie North America Ltd., a subsidiary of Macquarie Group of Sydney.</p>
<p>Including the oil sands project, Alberta generators have proposed construction of more than 5,000 MW of new electricity generation by 2005, which would far exceed expected demand and would permit the export of some 3,000 MW, according to provincial projections.</p>
<p>Nuclear generation already is key to some importing provinces, like Ontario. In a January 2003 projection of supply and demand for the following 18 months, the Ontario Independent Electricity Market Operator notes, "More significant than the demand changes are the delays announced in October (2002) to the restart of the shut down Pickering A nuclear units. These delays have reduced available generation substantially over the entire outlook period. … If the Pickering and Bruce nuclear units do not return to service as scheduled before next summer, supply will continue to be stretched thin."</p>
<p>Nuclear power could provide a growing share of electricity in Canada, where political opposition to the fuel source seems less vociferous than in the United States. In Ontario, for example, the restart of the twin 750-MW Bruce Power plants has been scheduled for April and June of this year. "In the Ontario market it is anticipated that 3,500 MW of nuclear power will be returning to service over the next three-plus years, so if all that returns, during off-peak we would expect Ontario would go from a net importer to a net exporter," Dalton says.</p>
<p>Still, in some provinces, nuclear power is less welcome. In British Columbia, a new energy policy unveiled in November 2002 indicates that nuclear power will not be permitted in the province. This could suggest that in provinces where hydro- traditionally a publicly managed asset-is a strong option for new capacity, neither publicly nor privately financed nuclear projects may be feasible.</p>
<p>Similarly, a host of gas-fired plants also are scheduled to open across the country over the near term. In power-hungry Ontario, for example, the 578-MW ATCO Brighton Beach unit is scheduled to come on line in March 2004, and the smaller 98-MW Imperial Oil unit is slated for an April 2004 startup.</p>
<h3>Merchant Plants To Gain Ground</h3>
<p>Since the California debacle, private financiers' enthusiasm for merchant plants has waned in Canada, one source says. Cost recovery is the key. "From East to West there were a lot of merchant plant proposals, but there is not much activity now, and the biggest hurdle is firm contracts," Harvie says. But the provinces still are willing to sign longer-term contracts that can make merchant plants viable, given the province's responsibilities to its citizens.</p>
<p>In electricity-export-strong Quebec during 2002, the total volume supplied by purchase contracts with independent power producers amounted to only 387 MW. Hydro Quebec estimates that over the next few years, there will be only an additional 48 MW available from IPPs.</p>
<p>Similarly, in British Columbia, Canada's other export powerhouse, the province just recently decided to allow private sector participation in the development of generating assets in general, with the proviso that no more large-scale hydro projects will be approved.</p>
<p>Other provinces are less sanguine about the potential role of private sector equity in any hydroelectric projects. "Some provinces don't want to broach the subject of private money in hydro. Some provinces don't want to even go there. The politician who does bring it up doesn't want to stay in office very long," suggests one analyst.</p>
<p>While the mid-term outlook for U.S. imports of electricity from Canada is down, the longer-term view is somewhat brighter. Several new generating projects in Canada could breathe new life into exports to the United States. While some of these projects are based on merchant plant financing, others are expected to involve a higher level of provincial government capital, mitigating the risks resulting from the dearth of new long-term purchase contracts available in the North American market. And although Canadian generators depend mostly on hydroelectric potential for export sales now, an evolving mix of fuel sources also could help yield more exports, analysts say. Finally, new Canadian transmission assets under consideration could better link several provinces to the U.S. grid and help make Canadian electricity more competitive with U.S. generation.</p>
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Tue, 15 Apr 2003 04:00:00 +0000puradmin11191 at http://www.fortnightly.comPSC - Restructuring Ordershttp://www.fortnightly.com/fortnightly/1998/05-0/psc-restructuring-orders
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> PLANS OK'D for electric IOUs under New York's Competitive Opportunities docket. </p>
<p> CENTRAL HUDSON GAS &amp; ELECTRIC CORP. RETAIL CHOICE: Offered to 8 percent of total load in 1998; additional 8 percent each year; choice for all by July 1, 2001. SAVINGS: $10.5 million to fund 5-percent rate cut for large industrials; all other rates frozen (since 1993) through June 30, 2001. Earmarks $24.5 million for incentives for residential, commercial and small industrial classes. Generation backout rate is highest among IOU restructuring plans. DIVESTITURE: Must auction fossil generation by June 30, 2001. Company receives 5 percent of gross proceeds up to net book value, even if sale at a loss, plus 10 percent of gross proceeds above net book value, subject to $17.5 million cap. RETURN ON EQUITY: All earnings above 10.6 percent return on equity go to customers. OTHER: $3.5 million for system benefits (efficiency, environmental protection) for first 3 years of plan. See, Case 96-E-0909, Feb. 19, 1998 (N.Y.P.S.C.). </p>
<p> CONSOLIDATED EDISON OF NEW YORK, INC. RETAIL CHOICE: Begins June 1, 1998, for 500 MW of load; up to 1,000 MW by April 1, 1999; additional 1,000 MW by April 1, 2000; full implementation by Dec. 31, 2001, or when state achieves full operation of independent system operator, whichever comes first. SAVINGS: Immediate 25-percent rate cut for large industrial customers with monthly demand above 1,500 kW; 10-percent for commercial and general service customers (+1,500 kW) over 5 years; 10-percent for residential and small business by end of fifth year. Prior rate increases waived. Total savings between $1 billion and $1.5 billion over 5 years. DIVESTITURE: Company to sell at least 50 percent of in-city generating capacity; process was to begin by mid-April for 30 percent within 90 days. (Sell-off plan OK'd, Jan. 14, 1998, Case 96-E-0897, 183 PUR4th 159.) RETURN ON EQUITY: Approves 10.9 percent, with sharing of excess earnings triggered at 12.9 percent. OTHER: Plan expands company's Business Incentive Rate, making 65 MW available at reduced rates to encourage businesses to locate in ConEd's service territory. See, Case 96-E-0897, Opinion No. 97-16, Nov. 3, 1997 (N.Y.P.S.C.). </p>
<p> NEW YORK STATE ELECTRIC &amp; GAS CORP. RETAIL CHOICE: Begins Aug. 1, 1999 for all customers. SAVINGS: Large industrials get 5-percent annual rate cuts over 5 years. Rates frozen for residential and small commercial classes for 4 years, with 5-percent cut in fifth year. Overall customer savings put at $725 million ($522 million from foregone rate increases). Generation backout credit equals 3.23 cents per kWh through July 31, 2000; 3.47 cents until July 31, 2001; then 3.71 cents through end of settlement. DIVESTITURE: Company must sell its coal-fired generating plants by multi-round auction process by Aug. 1, 1999. Proceeds above book value will mitigate nuclear stranded costs; company may retain 20 percent of gain from renegotiation and/or termination of above-market purchased power contracts. RETURN ON EQUITY: Earnings above 9 percent return on equity trigger sharing with ratepayers. Cap imposed at 12 percent (all excess earnings go to customers). OTHER: Includes about $40 million in funding for system benefits charge for energy efficiency and public policy programs. See, Case 96-E-0891, Opinion No. 98-6, March 5, 1998 (N.Y.P.S.C.). </p>
<p> NIAGARA MOHAWK POWER CORP. RETAIL CHOICE: Begins in 1998 for large industrial and commercial customers; available for all by Jan. 1, 2000. SAVINGS: Immediate 25-percent cut for the very largest industrial and commercial customers. By 2000, all industrials to save about 13 percent, versus 3.2 percent for residential and small commercial classes (many of whom may see no decrease, and perhaps an increase). PSC defers final decision on proposed customer charges for residential and small commercial classes that would produce net rate increase in some cases. Order admits that generation backout rate is "low" (reflects fuel costs and wholesale prices in New York Power Pool) but rejects Enron proposal for higher rate of 3.95 cents per kWh, reflecting property taxes and higher NYPP reserve margin (18 percent, up from 14 percent). DIVESTITURE: Company may retain 15 percent of any gain above net book value as incentive for sale of non-nuclear generation. Nuclear generation would remain with the regulated T&amp;D company. RETURN ON EQUITY: Company assumes $2 billion in stranded costs by accepting "very low" equity return over 5 years. OTHER: Approves "floating" competitive transition charge to fund $3.6-billion debt needed to execute settlement with 16 independent power producers to restructure uneconomic purchased power contracts. Exit fees and backup service charges for on-site generators designed to make CTC nonbypassable. Provides third-party administrator for system benefits charge. Set up $10 million fund for employee retraining/outplacement/severance. See, Case 94-E-0098, Opinion No. 98-8, March 20, 1998 (N.Y.P.S.C.). </p>
<p> ORANGE &amp; ROCKLAND UTILITIES INC. RETAIL CHOICE: Begins May 1, 1998; offered to all by May 1, 1999. Company to file plan to make billing/metering services competitive by May/December 1999. SAVINGS: Large industrials can realize average price of 6 cents/kWh (assumes 8.5 percent cut). For "all other customers," rates cut 1.09 percent in first year, 1 percent in second, following other recent cuts. $32.4 million in total customer rate cuts over 4 years ($21.6 million for residential and small business). DIVESTITURE: Assumes transfer of generation by May 1, 1999. Gains accrue first to "all-other" group (see above), up to equivalent of 5 percent rate cut. Portion of uneconomic costs recovered through CTC, with CTC cut back if divestiture is delayed and expiring if no transfer by Oct. 31, 2000. No CTC if assets sold prior to May 1, 1999. RETURN ON EQUITY: Predicated on 10.4 percent. Ratepayers get 75 percent of excess earnings above 11.4 percent. OTHER: System benefits charge of about one mill per kWh ($3.2 million per year) funds demand-side management and other public policy initiatives. Offers $7.5 million for employee severance/retraining/outplacement. See, Case 96-E-0900, Opinion No. 97-20, Dec. 31, 1997, 182 PUR4th 201 (N.Y.P.S.C.). </p>
<p> ROCHESTER GAS &amp; ELECTRIC CORP. RETAIL CHOICE: Available to new customers and 10 percent of energy load for existing customers (all classes) by July 1, 1998; 20 percent by July 1, 1999; 30 percent by July 1, 2000; in full by July 1, 2001. SAVINGS: 10 percent rate cut for large industrials (to achieve average rate of 5.6 cents per kWh); 8 percent for small commercial (average rate 6.8 cents per kWh); 7.5 percent for residential and small commercial by final year of term; cumulative reduction of $64.6 million by July 1, 2001. Backout rate is 2.3 cents per kWh during energy-only stage (includes 1.9 cents plus retailing charge), to rise to 3.2 cents per kWh by July 1, 1999, equal to combined fixed and variable strandable non-nuclear generation costs, plus retailing costs (contingent on development of statewide market for energy and capacity). DIVESTITURE: Required for fossil and hydro generation. Shareholders keep 20 percent of any net gain on sale, but 40 percent of first $20 million if divestiture occurs quickly. Nuclear investments (Ginna, Nine Mile II) would remain in regulated T&amp;D company. RETURN ON EQUITY: Ratepayers receive 50 percent of excess earnings above 11.5 percent. OTHER: System benefit charge allowed for research and development, energy efficiency, low-income and environmental programs. Company must file market power mitigation plan with FERC. See, Case 96-E- 0898, Opinion No. 98-1, Jan. 14, 1998 (N.Y.P.S.C.). </p>
<p> (em Bruce W. Radford, editor </p>
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Fri, 15 May 1998 04:00:00 +0000puradmin9787 at http://www.fortnightly.comOff Peakhttp://www.fortnightly.com/fortnightly/1997/08/peak
<div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - August 1997</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Today's critics decry stranded costs, yet fail to cover their tracks.</p>
</p>
<p> Many of today's most vociferous critics of stranded cost recovery were once among the most ardent supporters of the nuclear plants they now disavow. </p>
<p> Back in the '70s, when electric utilities and regulators laid out their long-term plans, nuclear power played a leading role, and American industry largely concurred. Now, however, 20 years later, the business sector sings a new tune. "I told you so," the refrain goes. </p>
<p> Profits and lower rates are nothing to sneeze at, especially for high-volume electric consumers like Ford and Dow Chemical. But how does one explain the about-face of a group like the Heritage Foundation, the Washington think tank now pushing for electric deregulation? </p>
<p> In 1978, the Heritage Foundation decried cancellation of nuclear plants: "Without nuclear power we will be unable to maintain the level of economic growth necessary to ensure that all Americans will have an opportunity to fulfill the promise for the American Dream." A generation later, and the group had forgotten both its heritage and its foundation: "[S]tranded cost recovery is difficult to justify. ... Utilities ... argue that they have made investments in good faith ... little substantive evidence can be offered by these utilities." </p>
<p> When major industries, policy groups and analysts reverse field, after utilities have spent billions of dollars at their urgings, the least they can do is own up to their responsibility. What will these intellectual chameleons say during the next oil embargo, coal strike, drought or fuel shortage? In two decades will they tell us we should have listened to them and never deregulated? </p>
<p> The inter-generational linkages in this nation are growing more tenuous. Blatant hypocrisy from our leading businesses and thinkers only serves to weaken the ties that bind. t </p>
<p> Frank Clemente is senior member of the graduate faculty at Penn State University. He has presented his research findings on energy in professional journals, public conferences and testimony before various utility commissions. </p>
<p> What Did They Say, and When Did They Say It? </p>
<p> In the '90s In the '70s </p>
<p> We warned you: </p>
<p> • "Industrial consumers have long warned that electric utilities were wrong to overbuild generating facilities to maintain excessive reserve margins." (em American Iron and Steel Institute, Electricity Consumers Resource Council, and the Chemical Manufacturers Association, testimony before the FERC, December 1994. </p>
<p> We didn't ask for it: </p>
<p> • "[I]t is not fair to ask retail customers to bear the full burden of a utility's stranded costs. ... They did not ask for, support or sign for the high cost nuclear plants ... [and] actually opposed such high-cost projects when they were originally conceived." (em Ford Motor Co., representing ELCON,* before U.S. Senate Committee on Energy, March 1997. </p>
<p> Chemical Industry: </p>
<p> • "For companies in the chemical process industries whose plants run on big inputs of electrical energy, the outlook is now marred. ... During the next decade or even longer, unavailability of low-cost electricity may prevent them from adding new capacity when and where they want. Reason: Many large utility companies have been postponing major projects for additional generating capacity." (em CHEMICAL WEEK, 1974. </p>
<p> • "[F]ailure to exploit nuclear power to the fullest may result in electric power shortages in the decades immediately ahead." (em Dept. Of Commerce Energy Advisory Panel, chaired by Malcolm Pruitt, v.p., Dow Chemical, 1974. </p>
<p> Glass Industry: </p>
<p> • "The feeling is that we have to get out of natural gas. Electric power will be our future energy." (em Corning Glass executive quoted in the WALL STREET JOURNAL, 1975. </p>
<p> • "All electric melting looks better all the time." (em GLASS WORLD, 1974. </p>
<p> Automotive Industry: </p>
<p> • "Nuclear generation of electricity must continue to expand." (em A National Strategy, committee for Economic Development, whose trustees include executives of Ford, GM, and Chrysler, 1977. </p>
<p> • Henry Ford II said his company postponed plans to enlarge several of its Ohio plants because electric utilities there were having trouble getting new power plants approved and could not guarantee supply. "If ecologists are going to block these kinds of programs, then they will have to take responsibility," 1973. </p>
<p> Steel Industry: </p>
<p> • "[T]his statement will indicate the sincerity of the steel industry in cooperating with the Federal Energy Administration in the development of its blueprint for achieving energy independence through the use of nuclear power in the 1980s." (em George A. Stinson, chair, National Steel Corp., 1974. </p>
<p> • "We believe nuclear energy, like coal, is a great resource for the future." (em IRON AND STEEL MAKER, 1977. </p>
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Fri, 01 Aug 1997 04:00:00 +0000puradmin10335 at http://www.fortnightly.comTrendshttp://www.fortnightly.com/fortnightly/1996/02-0/trends
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Kent S. Knutson</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 15 1996</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Gas Garners
<p>Big Share of '95 Fuel Mix </p>
<p> For the second year in a row, natural gas fueled an increasing share of U.S. electric generation. When the final numbers are tabulated for 1995, electric generation is expected to have increased about 2.7 percent over the previous year. This compares to a 0.98-percent increase for the 1993-1994 period. Gas accounted for over 10 percent of the 1995 utility fuel mix (em up from 8.8 percent just two years ago. And for perhaps the first time in history, coal burn by utilities should remain flat despite robust growth in electric generation. </p>
<p> The fuel mix winners of 1995 were nuclear, hydro, and natural gas. Gas benefited primarily from decreasing prices, while the increase in nuclear output can be attributed to improved performance and more timely maintenance and refueling schedules. </p>
<p> Until the mid-December surge in gas prices (em driven by cold temperatures that triggered supply constraints in the Northeast (em prices for natural gas had steadily declined since February 1994. After reaching 273 ¢/MMBtu two years ago, average delivered gas prices continued to decline by more than 32 percent, bottoming out at 180 ¢/MMBtu in September. Over the same 18 months, oil prices remained relatively flat, averaging over 254 ¢/MMBtu in September. </p>
<p> During the first three quarters of 1995, gas-fired generation was running 25.4 billion kilowatt-hours (bKwh) higher than in the same period in 1994. Gas-fired generation increased most in the South Atlantic (up 12.2 bKwh), displacing oil </p>
<p> (-15.4 bKwh). Gas burn also increased significantly in the West South Central region, particularly Texas, where gas (up 9.3 bKwh) combined with nuclear (up 9.6 bKwh) to displace coal-fired generation (down 5.6 bKwh). In the Mid-Atlantic utility fuel market, gas burn increased (up 8.4 bKwh) while both oil (down 7.5 bKwh) and nuclear declined (down 7.2 bKwh). Only in California did gas decline, while hydro rebounded to post a three-quarter increase of over 21.8 bKwh. </p>
<p> Ironically, coal's lackluster performance in a relatively strong year for electric demand has come about despite competitive spot prices. Spot coal prices remained relatively stable throughout the year, ranging between 114 and 118 ¢/MMBtu delivered. Yet even at these prices, spot coal consumption declined by 15 percent. </p>
<p> Nuclear generation for the first three quarters of 1995 ran 32.6 bKwh ahead of the same period in 1994. Already by September, eight power plants had recorded increases of over 3 bKwh. Topping the list were Houston Light &amp; Power's South Texas facility (up 6.2 bKwh) and Cleveland Electric Illuminating's Perry station (up 4.8 bKwh). And during the third quarter alone, the Palo Verde plant operated by Arizona Public Service Co. generated over 8 bKwh (em the highest quarterly output of a U.S. nuclear power plant on record. Only two plants recorded significant decreases in electric generation: Maine Yankee (down 4.6 bKwh) and Public Service Electric &amp; Gas's Salem plant (down 4.2 bKwh). </p>
<p> Last spring, Resource Data International projected gas to play a significant role as an electric fuel if prices stayed competitive. During 1995, gas prices were competitive and utility demand for gas </p>
<p> increased. We also predicted that hydro would rebound and play a significant role in the electric fuel mix. It did. Finally, we suggested that coal demand from electric companies would increase if spot coal prices continued to decline. Coal prices did remain competitive; however, demand stayed flat due to an abundance of nuclear- and hydro-generated electricity and competitively priced gas. </p>
<p> How coal contributes to the fuel mix in 1996 will depend in large part on the price competitiveness of gas, available hydro generation, and nuclear performance. Despite a record performance in 1995, more than half of the nation's 69 operating nuclear plants were down for refueling or maintenance at some point during the year. Clear evidence of faster refueling and maintenance schedules suggests another strong year for nuclear's contribution to the utility fuel mix. t </p>
<p> Kent Knutson is senior vice president at Resource Data International, Inc., an energy industry consulting and information management firm specializing in market and competitor analysis.</p>
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Thu, 15 Feb 1996 05:00:00 +0000puradmin8330 at http://www.fortnightly.comThe Choice of Fuel in Competitive Generationhttp://www.fortnightly.com/fortnightly/1995/06-0/choice-fuel-competitive-generation
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Hon. Richard D. Cudahy</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 15 1995</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>All versions of the "revolution" in the electric power industry seem to turn on the prospect of competition in generation. This indeed is the vision of things to come.1 The generation in question is either partly utility owned and partly independent or (em in the best of all possible worlds (em all independent, as a result of disintegrating the vertical utility monopoly.2 </p>
<p> The startling disparities between the cost of delivered kilowatt-hours in the various utility service territories supply the driving force behind the demand for competitive opportunity and access. Many observers now claim that the "market" price of electricity lies somewhere in the 4 cents per kilowatt-hour (›/Kwh) range, while, in certain service territories, retail rates may range upwards of 10 to 12 cents per kilowatt-hour.3 In general, we are to believe that there is "efficient" generation, which is usually ascribed to more competent management, and "inefficient" generation, which is normally attributed to a correspondingly backward management.4 No wonder there is a demand for competition if good management and bad management can be so sharply distinguished at the bottom line. </p>
<p> The literature on competition, however, has mostly failed to address the specifics of efficiencies in electric generation or the ways in which electric generation will respond to a competitive environment. </p>
<p> Heat Rates, Efficiency, and Vulnerability </p>
<p> Some discussions of this subject have made passing references to heat rates (em the standard measure of power-plant thermal efficiency (in British thermal units per kilowatt-hour). On the face of it, heat rates seem the natural measure of a factor that would respond to competitive forces. Heat rate is a conventional standard and, of course, may be adversely affected by environmental requirements. Increasing plant reliability, lowering fuel costs, and lowering financing costs have also been mentioned as sources of competitive savings.5 But, aside from obvious measures like these, the generation most authors consider vulnerable to competition is nuclear power.6 The question is whether high-cost generation resulted primarily from managerial error or from global factors unlikely to be "corrected" by market factors alone? </p>
<p> Nuclear generation is frequently identified as inefficient or costly. Disparities in the rate levels in adjoining service territories are often attributable to a too-expensive or poorly functioning nuclear unit or units in the disadvantaged territory. Under a competitive regime, this situation may mean that, at best, a nuclear plant can be run to recover its variable cost of operation, hopefully with some contribution to fixed costs. At worst, in the unlikely event the "market" price will not cover even variable costs, the nuclear plant will be wisely shut down. How decommissioning costs will fit into this picture is not entirely clear.7 </p>
<p> The number of nuclear plants continuing to run but failing to recover their total costs (including fixed costs) creates a national problem not unlike that of the railroads during the Depression. Utilities are expected to operate with substantial excess capacity and a chronic inability to achieve sufficient revenues to cover costs. The existence and extent of loss depend, of course, on how stranded assets, such as nuclear plants, are actually treated. </p>
<p> But all this is another subject. What seems most useful now is to work through the practical effects of competition as it might affect such likely victims as nuclear plants, and to discern what all this means for the specific areas where sunk costs would become unrecoverable in the face of competition. </p>
<p> The Nuclear Irony </p>
<p> We have all been brought up to believe (em and I think with some basis in history (em that competition is a wonderful stimulus to innovation. This is presumably what Joseph Schumpeter had in mind when he described capitalism as a process of creative destruction.8 His theory posits that a succession of waves of discovery of whole new ways of doing things creates the dynamism of competitive systems. The fact that the nuclear plant is the most radical innovation in electric generation (em at least since World War II (em is therefore a bit ironic. These plants now seem to have become the most obvious sources of loss and financial strain in the electric industry. Hardly the cutting edge of progress and change, many of the plants now vastly complicate any transition to a competitive mode. </p>
<p> Arguably the most spectacular and initially promising innovation in electric generation, nuclear generation was also fostered by a great deal of governmental encouragement and promotion. At one time, the peaceful uses of atomic energy occupied a very high priority in government and public thinking (em not only in the United States, but around the world. The nuclear power plant seemed an obvious and important avenue for hope for the future. As I recall, the late Shah of Iran favored it as a means of modernizing his country. I need not remind the reader of the promises of electricity "too cheap to meter," or the forecasts lauding the atom as a pollution-free substitute for coal.9 </p>
<p> The Energy Reorganization Act of 1974 divorced the promotional aspects of nuclear power from its regulatory aspects and created the Nuclear Regulatory Commission (NRC).10 That legislation contained a provision for the study of "nuclear energy center sites," which were conceived as regional areas for locating a number of nuclear reactors and/or other nuclear fuel cycle facilities. (On a more bucolic note, these areas were sometimes referred to as "nuclear parks.") The study mandated by Congress extended to soliciting the views of officials and experts at all levels as well as those of "interested persons" and "citizens' groups."11 To facilitate the gathering of this information, the NRC convened several large conferences of interested citizens and responsible officials. </p>
<p> At that time, if memory serves, popular theory conceived a need for 800 nuclear power plants (em or possibly as many as 1600. A view that it would be better to build these plants in clusters of about </p>
<p> l0 or 25, possibly including reprocessing facilities and the like, also enjoyed some attention. Such a disposition promised to concentrate the safety and environmental problems in sites away from populous areas. The purpose of the conferences was to think through the problems of infrastructure, security, regulation, and other pertinent aspects of these proposed "nuclear parks." I attended one of these conferences in 1975 (em in Portsmouth, NH. The participants (em of whom only a minority were government officials (em thought that we were dealing in a frightening but possibly inescapable reality. We, and the agencies and experts that guided us, were, of course, wrong (em wholly misguided. But a belief in the need for nuclear power, as well as anxiety about its impacts, is what concerned agencies and "interested" citizens 20 years ago. And the electric utility industry itself certainly held no contrary view. Almost everyone (em not merely "government" or "management" (em entertained these ideas. Yet, after all that, we now view nuclear power, not as the energy giant on the horizon, but as the most obvious candidate to become a "stranded asset" in the new era of competition. </p>
<p> The Natural Gas Turnaround </p>
<p> Presumably, combined-cycle gas-turbine generation will establish the marginal cost (em and hence the market price (em of electricity under a competitive regime.12 Natural gas plants are both the cheapest and the fastest plants to build (em and the costs of fuel are currently favorable. I have heard no one predict that the output of these plants will be too cheap to meter, but, considering the enthusiasm of some prophets of a new order in electricity, I expect some such prediction any day now. Natural gas has, of course, always been a highly desirable fuel (em environmentally benign, yet chock full of energy. The only questions in the past have been "How much of it is there?," and "Can its price remain competitive?" </p>
<p> At the time nuclear power parks were drawing the attention of the "interested" community, popular thought placed natural gas on the endangered species list. The then current wisdom suggested that the supply of gas was shrinking and that prices were mounting in the face of all government efforts to suppress them. Natural gas was a "premium" fuel to be saved for home-heating or agricultural use; using it at a power plant was thought to verge on criminal behavior.13 In any event, the price of natural gas was rising so rapidly that the thought of competition with nuclear generation was absurd. Gas turbines were as cheap and as fast to build as they are now, but certainly no one saw them as a major factor in fashioning the energy future. All the emphasis was on coal and nuclear generation as best comporting with national security objectives (em not to mention cost. Almost everyone thought that dependence on Middle Eastern oil put the nation at risk (em if not of an actual embargo, at least of an exorbitant price. Then, all estimates of oil and gas prices for the future assumed a rising trend. In light of the bleak outlook for gas and oil, Congress passed the Powerplant and Industrial Fuel Use Act of 1978, which aimed at converting natural gas- and oil-burning power plants to coal, or to some other fuel with a future.14 These pessimistic views of the prospects for oil and natural gas were rather generally held by the electric power industry and the public, as well as the government. </p>
<p> The course of events since 1975 is, of course, well known. A number of huge baseload nuclear plants became redundant because electric demand fell far short of forecasts. Nuclear costs (em whether due to poor construction management or to regulatory waffling (em climbed out of sight. Meanwhile, natural gas, freed of an earlier regulatory regime, began to fill the interstate pipelines. Gas surpluses and price declines developed. Gradually, there seemed to be enough of the "premium" fuel to find a broad range of satisfactory uses (em even in power plants. In fact, in the last year or so, estimates of crude oil prices (and presumably natural gas prices) forecast a declining trend.15 Now there appears to be sufficient oil and gas to last literally forever (em and at cheaper and cheaper prices. In contemplating the competitive universe, the combined-cycle natural gas-fired turbine appears to be the plant at the margin (em setting the market price and exposing many nuclear behemoths as an embarrassment. In 20 years, conventional thought, which was by no means confined to government regulators or the electric power industry, has suffered a total reversal. </p>
<p> A New Pecking Order? </p>
<p> I wish I could believe that we are really smarter in 1995 than we were in 1975. But I think the real lesson of history is that prediction is a very imperfect science; it is virtually impossible to provide an accurate 20-year forecast. This is one reason a competitive regime faces what I consider unusual difficulties in the electric power industry. Perhaps these problems are no more serious in a competitive regime than in a regulated one. Yet these problems make one wonder just how different one regime may be from the other. </p>
<p> I make this observation because many of the cost differentials in generation hinge on choice of fuel. But the choice of fuel is dictated by a complex array of factors (em such as perceived national security, environmental, and available resource base considerations not necessarily reflected in the day-to-day market price. As I have pointed out elsewhere, these considerations, like externalities, potentially undercut decisionmaking in the electrical world.16 </p>
<p> So the market for electric generation promises to be heavily constrained and regulated. Unless the past has no message for the future, we will find ourselves in a market where choice of fuel (em certainly a major factor in competitive performance (em will be heavily impacted, if not dictated, by government policy (and by public opinion). Government policy, in turn, will be determined by current estimates of availability of various fuels, fuel price trends, dependence on foreign sources, national security considerations, and other nonmarket factors. Perhaps current thinking about these matters will prove more durable than past thinking, but there seems to be no guarantee of stable views. </p>
<p> For instance, deregulation of natural gas and the unbundling of gas pipeline services partially prompted the trend toward natural gas as a boiler fuel. Some believe that deregulation will save us from repeating the "errors" of the past (e.g., substituting other fuels for gas). True marketeers hold that the substitution of market forces for "command and control" assures, if not infallibility, at least alignment with a wondrously reliable invisible hand. This is an act of faith that only experience can put to the test. But the historical record suggests caution. </p>
<p> Quite apart from public policy involving world and domestic supply and considerations of national security, we also face major issues of safety and environmental impact. Public opinion and the government's outlook on these matters changed the prospects of nuclear energy rather dramatically between 1960 and 1990. Markets will have to operate within these changing constraints (em presumably discounting them as much as possible. The fundamental question of electricity's place in the energy pecking order is also open. How many gasoline-powered automobiles will bereplaced by electric cars? Again, extra-market forces will be in play. </p>
<p> The Real Promise of Competition </p>
<p> Obviously, the builders and buyers and sellers of electric generation will try to take government policy and public perception into account in arranging long-term contracts. But the factors we have mentioned are matters that markets, with their short-run focus, do not adequately reflect. The cheapest source today may be unavailable tomorrow because of some shift in the politics or economics of world trade. All industries risk an uncertain future (em dress manufacturers must guess what may be in style next season (em but no industry is more fundamental to the economy, or to national security, than the electric industry, which has massively capital-intensive investments at stake. </p>
<p> Admittedly, competition in generation may take place primarily at the level of heat rates and the like; these do not raise such serious and fundamental questions. Choice-of-fuel questions may not be a major factor because the mix of competing generating plants will be uniform and optimal; then competition will occur at the margins.17 But this does not seem obvious to me, and such an assumption should not be lightly made. </p>
<p> As I have indicated, the real promise of competition is in Schumpeter's "creative destruction" (em the belief that whole new ways of doing things will emerge from the competitive struggle and, as a consequence, drastically improve quality, reduce price, or provide other benefits. On the whole, this has not been the story of electric power to date. Incremental progress (em bigger units and higher pressures (em has been the norm. The giant leaps we have seen (em such as the development of nuclear power (em have thus far produced more failure than success. Somehow the electric industry's record has not paralleled that of the telecommunications industry, where major innovation has been spectacularly successful. </p>
<p> One possible reason for this is the extraordinary impact of electricity on the world it pervades (em on the environment in the largest sense. One power plant may be narrowly more "efficient" than another, but should it raise havoc with the environment, national security, or any number of other matters external to the market, extraordinary complications will arise. We must be vigilant to ensure that our thinking about a more competitive electrical generation system addresses with realism the many important constraints that system will face. t </p>
<p> Richard D. Cudahy is a judge at the U.S. Court of Appeals for the Seventh Circuit. Previously, Judge Cudahy served on the Wisconsin Public Service Commission (1972-75), including a stint as chairman (1974-75). Judge Cudahy thanks law clerk Karen Chisholm for assistance in preparing this article.</p>
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Thu, 15 Jun 1995 04:00:00 +0000puradmin9282 at http://www.fortnightly.com